Fiber-optic sensors are increasingly being used as devices for sensing some quantity, typically temperature or mechanical strain, but sometimes also displacements, vibrations, pressure, acceleration, rotations, or concentrations of chemical species. The general principle of such devices is that light from a laser is sent through an optical fiber and there experiences subtle changes of its parameters either in the fiber or in one or several fiber Bragg gratings and then reaches a detector arrangement which measures these changes.
The growing interest in fiber optic sensors is due to a number of inherent advantages:                Inherently safer operation (no electrical sparks)        Immunity from EMI (electromagnetic interference)        Chemical passivity (not subject to corrosion)        Wide operating temperature range (wider than most electronic devices)        Electrically insulating (can be used in high voltage environment)        
Fiber optic sensors deployed in wells are predominately calibrated before being deployed down hole. After calibration such sensors are often permanently installed behind a well casing or they are attached to the down hole tubing. As down-hole conditions change over time, some of these installed sensors may experience high temperatures, high pressures and various chemicals that may impact the installed sensor performance.
The sensor itself will often get calibration coefficients that are unique to the sensor, and these calibration coefficients are used in the interrogation unit to achieve desired accuracy and resolution. Many sensors must periodically be calibrated due to component drift either in the sensor itself or the interrogation unit. In some cases, it is beneficial to calibrate the sensor and the interrogation unit as a pair. Sensors permanently installed in oil & gas wells cannot be removed for calibration, and estimated annual drift requirements are applied to the sensing system.
There are economic advantages to having a method for re-calibrating such down-hole sensors. For example DTS systems are usually calibrated with each fiber during or prior to deployment. To replace a DTS system where you have up to 16 sensing fibers/wells connected would be a challenging task due to the calibration. The method proposed herein would allow in-situ calibration of the DTS system and the sensing fiber in case the DTS system or the fiber would need to be replaced.
Thus a need exists for ways to re-calibrate downhole sensing systems in-situ, without having to remove the sensors from the downhole environment.